A variety of techniques have been used to enhance the recovery of petroleum from subterranean formations in which the petroleum no longer flows by natural forces. Such techniques can include water injection and/or subsequent gas flooding, among others. Water injection can be useful to recover some petroleum, however, only about a third of the petroleum are recovered using this technique. As such, typically water injection procedures are followed by gas flooding procedures. Gas flooding can be performed with a miscible gas, to reduce the viscosity of the petroleum present in the subterranean formation in order to increase the flow of petroleum to a production well. Carbon dioxide, which acts as a solvent to reduce the viscosity of the petroleum, is one of the most effective, and least expensive, miscible gases.
Gas flooding, however, can be accompanied with a number of drawbacks. One main problem encountered is poor sweep of the subterranean formation. Poor sweep occurs when the gas injected into the subterranean formation during a gas flooding process flows through the paths of least resistance due to the low viscosity of the gas, thus bypassing significant portions of the formation. This issue of poor sweep can further be compounded if the mobility ratio (i.e., the ratio of relative permeability to viscosity) between the petroleum and the injected gas is high. When the mobility ratio is high or low (e.g., out of balance) the less viscous material tends to finger through the viscous one, which further limits recovery of the petroleum.
When the injected gas bypasses significant portions of the formation and/or fingers through the petroleum due to a poor mobility, less of the petroleum is contacted with the gas, reducing the likelihood that the gas will reduce the viscosity of the petroleum. Thus, the gas injected during the gas flooding process is meant to “sweep” the petroleum toward the production well by lowering the viscosity of the petroleum. However, when the gas does not contact a large portion of the petroleum contained in the subterranean formation, a large portion of the petroleum in the subterranean formation is left behind, producing poor sweep. In addition, due to the low density of the gas, the injected gas can rise to the top of the formation and “override” portions of the formation. This can then lead to early breakthrough of the gas at the production well and increased production costs associated with and surface handling and cycling of the gas.
To enhance the gas flooding process effectiveness, it has been suggested that the overall efficiency of a gas flooding process can be improved by including a foaming agent or surfactant to generate a dispersion in the formation. A dispersion can generate an apparent viscosity of about 100 to about 1,000 times that of the injected gas improving the mobility ratio. As such, the dispersion can force the gas to drive the recoverable hydrocarbons from the less depleted portions of the reservoir toward the production well. Further, the dispersion can inhibit the flow of the gas into that portion of the subterranean formation that has previously been swept. In other words, the dispersion can serve to block the volume of the subterranean formation through which the gas can short-cut, thereby reducing its tendency to channel through highly permeable fissures, cracks, or strata, and directing it toward previously unswept portions of the subterranean formation. This can also increase the recovery of hydrocarbons from the formation.
The surfactants used in gas flooding processes, however, have suffered from a number of drawbacks. For example, traditional surfactants, such as ethoxy-sulfates, tend to create unstable dispersions in the subterranean formation. An unstable dispersion can break and/or dissolve in the subterranean formation, allowing the gas from the gas flooding process to flow into the paths of least resistance, leading to early breakthrough and poor sweep, as discussed herein.
Another problem encountered by prior art surfactants has been the selection of anionic surfactants that have a high affinity to formation rock within the reservoir, for example, carbonate. Surfactants with a high affinity to formation rock can adsorb into the formation rock, leading to surfactant loss. Without the surfactant present, there is less likelihood of forming dispersion within the reservoir, also leading to early breakthrough and poor sweep, as discussed herein.